Oil production companies extract heavy oil by surface mining or various known in situ techniques. Heavy oil is used herein to refer to oil and/or bitumen that are trapped within oil sands and other forms of petroleum hydrocarbons that demonstrate high viscosities under normal reservoir conditions. One known in situ technique is steam assisted gravity drainage (SAGD).
In a typical SAGD project, two parallel wellbores are drilled from respective surface wellheads into a target reservoir that contains the heavy oil. The target reservoir can be multiple hundreds of meters below the surface. The two wellbores deviate from a generally vertical orientation through a turn section and then the paired wellbores extend substantially horizontally though the targeted reservoir. The section of the wellbore that includes the turn section may be referred to as the heel of the wellbore. The end of the horizontal section that is furthest from the wellhead may be referred to as the toe of the wellbore. The horizontal sections of the two wellbores are typically separated by a several meters, for example around 5 meters, with an upper horizontal wellbore section and a lower horizontal wellbore section.
The wellbores may then be completed with various types of casing and liners to form two completed wells.
Steam is injected into the wellhead that terminates in the upper horizontal wellbore within the target reservoir for thermally mobilizing the heavy oil. This well may be referred to as the injection well. The steam exits the injection well and decreases the viscosity of the heavy oil in the surrounding target reservoir. The less viscous hydrocarbons are then mobilized and flow, under gravity, into the lower well. The lower well is referred to as the production well. The production well typically includes an artificial lift system to pump the collected hydrocarbons, gas, produced water and condensed steam up to surface. The artificial lift systems typically include a downhole pump that is located at or near the heel of the production well.
Within the injection well and the production well, further substantially parallel strings of tubulars may be included. For example, a long tubing string may extend from the wellhead to terminate at or near the toe of the well. The long string provides unrestricted access to the toe of the well. Additionally, a short tubing string may extend from the wellhead and terminate at or near the heel of the well. In this arrangement, steam can be introduced into the toe of the injection well by an injection long tubing string and steam can be introduced in the heel of the injection well by an injection short tubing string. Steam may also be circulated between the long and short injection strings. Similarly, there can be a long production tubing string and a short production tubing string. Typically, the long production string and the short production strings are used to circulate steam within the injection well during start up, which is prior to an injection and production phase.
Some target reservoirs are deep enough below the surface and have sufficient reservoir pressure to produce heavy oil in a free-flowing phase that does not require a downhole pump. In these reservoirs, operators may use a concentric arrangement of the long producing tubing string positioned within the short production string. This concentric arrangement may be used until such time that the reservoir pressure decreases and an artificial lift system is required. At this point, the long production string may be pulled up hole and then reinserted in the parallel arrangement described above and the short string may also be pulled uphole to add the artificial lift system.
Operators of SAGD projects typically detect and measure various downhole parameters, such as pressure and temperature, within the injection well and/or the production well. Some of the known techniques and sensory apparatus for obtaining information regarding the downhole parameters include, but are not limited to: use of blanket gas; bubble tubes; various types of mechanical, electromagnetic and strain gauges; mineral insulated thermocouples; fiber optic cables which may act as sensors; fiber optic cables which may include further separate sensors; or combinations thereof. The information regarding the downhole parameters may be obtained from both of the heel and the toe of the production well.
The measured downhole parameters are used to assist in the operation of the downhole pump within the production well. For example, a pressure sensor that detects changes in a head pressure of a fluid column above the heel of the production well and can provide an indication as to the fluid levels within the production well. If the artificial lift system's pump output is too high, then the fluid levels within the production well may decrease, which may ultimately cause the downhole pump to burnout. Furthermore, if the pump output is too high that may cause the cold point between the injection well and the production well to creep downwards towards the production well. This creep may increase the changes of a steam flash, which can damage the production liner within the production well.
To obtain the measured information regarding the downhole parameters, an instrument line that includes one or more sensors can be inserted into the long production tubing string for detecting and measuring downhole parameters at the toe of the production well. Measurements from the heel of the production well provide pressure and temperature data that is captured in close proximity to the artificial lift system. The sensors for capturing downhole parameter measurements from the heel of the production well are typically externally connected to the outer surface of the short production tubing. However, for various reasons, the short production tubing string often requires one or more work-over procedures. For example, the short production tubing string may have to be pulled out of the production well because downhole pumps often require replacement and maintenance. In order to perform such replacement and maintenance, the downhole pump portion must be pulled up to surface and this work-over procedure can often times damage the sensors that are externally fixed on the short production tubing. Furthermore, the externally connected sensors require external connectors for securing the sensors to the outer surface of the short production tubing string. The external connectors often also get damaged and require replacement during any work over of the short production tubing string.